The known prior art solution WO 2009078745 A1 “Proppant flowback control using encapsulated adhesive materials” discloses a hydraulic fracturing method, wherein the sand flowback from a fracture is prevented by means of injecting an encapsulated tackifying agent mixed with a proppant into a subterranean formation. In the above known method, at the first stage, the fracture is filled with the proppant mixed with the encapsulated tackifying agent. The content of the tackifying agent ranges from 0.01 to 20% of the total amount of the proppant. The encapsulated tackifying agent and the proppant may be pre-mixed or mixed at the well site followed by introduction into the subterranean formation. At the second stage, the fracture closure pressure forces the capsules to break and release the tackifying agent.
The materials used to manufacture the shell for encapsulating the tackifying agent include polyesters, polyolefins, high and low-density polyethylene, and polypropylene. The shell may also be made of insoluble polymeric components, such as polyesters, polyarylates, polyamides, phenol-aldehyde resins, and mixtures thereof. Suitable thicknesses of the capsule shells range from 0.01 to 1 mm. Suitable dimensions of the capsules comprising the tackifying agents range from 0.25 to 3.36 mm.
The above known solution serves to prevent the proppant flowback from the fracture.
The prior art solution WO2012155045A3 “Destructible containers for downhole material and chemical delivery” describes a method of treating a downhole region penetrated by a wellbore with a treatment agent, wherein the method comprises: delivering the agent enclosed in one or more destructible capsules to the well site; placing one or more destructible capsules in the fluid to be injected into the well; and mechanically breaking one or more destructible capsules in the well or in the rock to release the treating agent. Also, a method of treating a subterranean formation penetrated by a well with a solid bridging material, which includes fibers, flakes, or specially selected blends of multisized particles, is provided, wherein the method comprises delivering the solid bridging material enclosed in one or more destructible capsules to the well site; placing one or more destructible capsules in the fluid to be injected in the well; and mechanically breaking one or more destructible capsules in the well to release the solid bridging material in the well.
The above known solution is intended to inject the bridging material into the fracture.
In the prior art solution WO2010020351A1 “Release of Chemical Systems for Oilfield Applications by Stress Activation”, a system is provided, which is employed in the hydrocarbon production, using the encapsulating material (B) and component (A), wherein the component (A) is contained within the above encapsulating material (B), and the above encapsulating material (B) is designed to break and release the component (A) if the pressure drops by more than 10 bars.
An embodiment of the above solution discloses the arrangement using the encapsulating material (B) and the component (A), wherein the component (A) is contained within the above encapsulating material (B). The system also includes the carrier fluid (C) that transfers said encapsulating material (B) and the component (A) contained therein, wherein said encapsulating material (B) is designed to break and release said component (A) under sufficiently stressed conditions.
The used encapsulating material (B) can be designed in the form of a flexible capsule made of gelatin, pectin, cellulose derivatives, acacia gum, guar gum, locust bean gum, tara gum, cassia gum, agar or n-octenylsuccinate, starch, porous starch, pectin, alginates, carrageenans, xanthan, chitosan, scleroglucan, diutan, and mixture thereof. In the embodiment of the above known solution, the encapsulating material comprises a mixture of gelatin and acacia gum. Gelatin to acacia gum mass ratio ranges from 9:1 to 1:9, in most cases from 5:1 to 1:5, first of all from 2:1 to 1:2, and the most acceptable ratio is 1:1. According to the above known solution, the capsule diameter ranges from 1 to 5,000 microns, in most cases diameter ranges from 10 to 2,000 microns.
The above known solution is used for delivery of chemical materials into the well during well drilling.
In-situ formation stress is measured by means of injecting the fluid into/out of the formation, fracturing, and measuring the fracture closure pressure. A review of such techniques can be found in (Veatch Jr., R. W. and Moschovidis, Z. A. 1986. An Overview of Recent Advances in Hydraulic Fracturing Technology. Presented at the International Meeting on Petroleum Engineering, Beijing, China, 17-20 March. SPE-14085-MS). These approaches are efficient for HF, but they are cost-intensive and complicated to employ in the course of well production.
In the prior art solution RU 2386023 C1 “A METHOD TO DETERMINE THE HYDRAULIC FRACTURE CLOSURE PRESSURE”, a method of assessing the fracture closure pressure by means of sending a series of pressure pulses into the well using surface equipment and sensing the well response to the pressure pulses by pressure gauges is provided. At the same time, the bottomhole pressure corresponding to each pulse is measured. An average fracture width is derived using a mathematical model of the pressure pulses propagation within the wellbore and the fracture. Moreover, a ratio of the simulated average fracture width to the derived bottomhole pressure is derived. This ratio is extrapolated to a zero-width point, while the closure pressure is determined as a bottomhole pressure corresponding to the zero width.
The above solution may be used in the condition of open fracture, which can be achieved by means of injecting fluid into the well (well intervention).
The prior art solutions do not provide any techniques directed to using capsules filled with various marker agents (tracers) and characterized by different breaking strengths corresponding to these marker agents to determine the fracture closure pressure both during well stimulation by hydraulic fracturing and in the course of the long-term monitoring of the reservoir pressure associated with the reservoir depletion due to the hydrocarbon production in the well. Additionally, no information is disclosed regarding capsules injecting into the hydraulic fracture and release of the marker agents from the capsules with the breaking strength below the current closure pressure in the fracture, as well as detecting the marker agents produced at the surface and matching the marker agents to the corresponding value of the fracture closure pressure.
Alternative prior art solutions designed to measure the fracture closure pressure without using the marker agents involve well operation intervention, for example, by injecting the fluid into the fracture.
Knowledge of the main stresses in the formation and determining the fracture closure pressure due to the fracture closure it is found out at stages of well operation with hydraulic fracturing. During well stimulation: it determines the proppant strength, the fracturing pressure, and the fracture direction. During the production operations, it helps to predict stability and sand production in the well.
Therefore, there is a interest in a low-cost and non-invasive technique to determine the fracture closure pressure both during the well stimulation by hydraulic fracturing and during the long-term monitoring of the reservoir pressure associated with the reservoir depletion due to the hydrocarbon production in the well.